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Final Report – Queensland and South Australia System Separation on 25 August 2018

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Final Report – Queensland and South Australia System Separation on 25 August 2018 Final Report – Queensland and South Australia system separation on 25 August 2018 10 January 2019 An operating incident report for the National Electricity Market Important notice PURPOSE This is AEMO’s final report of its review of the separation and load interruption events that occurred on 25 August 2018, as a ‘reviewable operating incident’ under clause 4.8.15 of the National Electricity Rules (NER). This report is based on information available to AEMO up to the date of publication. DISCLAIMER Any views expressed in this final report are those of AEMO unless otherwise stated and may be based on information and performance data recorded by AEMO’s own systems or given to AEMO by registered participants and other persons. Accordingly, to the maximum extent permitted by law, AEMO and its officers, employees and consultants involved in the preparation of this update report: make no representation or warranty, express or implied, as to the currency, accuracy, reliability or completeness of the information in this update report; and, are not liable (whether by reason of negligence or otherwise) for any statements or representations in this update report, or any omissions from it, or for any use or reliance on the information in it. COPYRIGHT © 2019 Australian Energy Market Operator Limited. The material in this publication may be used in accordance with the copyright permissions on AEMO’s website. Executive summary This is AEMO’s final report on the events that occurred across the National Electricity Market (NEM) power system on 25 August 2018. This event saw the loss of the alternating current (AC) interconnector between the Queensland (QLD) and New South Wales (NSW) regions, followed by loss of the AC interconnector between South Australia (SA) and Victoria (VIC). The two separation events resulted in the interruption of electricity supply to industrial loads in VIC, NSW, and Tasmania (TAS), and some residential and commercial customers in NSW. This document supersedes AEMO’s preliminary report released on 10 September 2018. This report provides data-based analysis and insights about the initiating cause of the event and subsequent performance of the power system. Based on this analysis AEMO has identified specific risks that compromise the power system’s resilience to major frequency events. The event highlights a deficit of primary frequency control response from NEM generation, compared with historic levels and with other power systems around the world. AEMO makes eight recommendations for action and further investigation to improve system resilience. References to times in this report, unless otherwise specified, are to Australian Eastern Standard Time. Events of 25 August 2018 On Saturday 25 August 2018, there was a single lightning strike on a transmission tower structure supporting the two circuits of the 330 kilovolt (kV) Queensland – New South Wales interconnector (QNI) lines. The lightning strike triggered a series of reactions creating faults on each of the two circuits of QNI at 13:11:39. The QLD and NSW power systems then lost synchronism, islanding the QLD region two seconds later, at 13:11:41. At the time, 870 MW of power was flowing from QLD to NSW. QLD experienced an immediate supply surplus, resulting in a rise in frequency to 50.9 Hertz (Hz). The remainder of the NEM experienced a supply deficit, resulting in a reduction in frequency. In response to the reduction in frequency in the remaining interconnected regions: The frequency controller on the Basslink interconnector immediately increased flow from TAS to VIC from 500 MW up to 630 MW. This created a supply deficit in TAS, causing the disconnection of 81 MW of contracted interruptible load under the automatic under-frequency load shedding scheme (AUFLS2) to rebalance the TAS power system at 13:11:46. The SA–VIC interconnector at Heywood experienced rapid changes in power system conditions that triggered the Emergency APD Portland Tripping (EAPT) scheme. The scheme responded to those conditions, as designed, to separate the SA region at Heywood. This occurred some 6 seconds after the QNI separation at 13:11:47. At the time of separation at Heywood, SA was exporting power to VIC. This meant there was a supply surplus in SA immediately after separation, causing frequency to rise. In the remaining VIC/NSW island, the resulting supply deficit caused frequency to fall below 49 Hz, triggering under-frequency load shedding (UFLS) to rebalance supply and demand across those regions. A total of 997.3 MW of supply was interrupted in VIC and NSW, comprising 904 MW of smelter load in both regions and 93.3 MW of consumer load in NSW. The SA-VIC interconnection was restored at 13:35 on 25 August 2018, and QNI at 14:20. The interrupted TAS load commenced restoration at 13:40 and the NSW and VIC smelters were permitted to reconnect at 13:33 and 13:38 respectively. All NSW consumer load was restored by 15:28. This event created three separate frequency islands on the mainland NEM and highlights the present challenges of controlling frequency in the NEM, and the potential consequences of the reduction of primary frequency control over a number of years. © AEMO 2019 | Final Report – Queensland and South Australia system separation on 25 August 2018 3 Frequency response Frequency is a measure of how well supply is matched to demand. Frequency in the NEM must be maintained very close to 50 Hz to support stable operation. The frequency operating standard (FOS) allows for small deviations at various levels for classes of events that can occur, including contingencies and islanding. The amount of deviation as a result to a disturbance is a measure of the resilience of the system, which can be managed with primary and secondary control mechanisms. In conventional power systems around the world1 frequency control has three distinct components: a) inertial response (instantaneous), b) primary frequency response (within 10 seconds and up 30 seconds) c) secondary frequency response (within 30 seconds and up to 30 minutes). An illustration of these kinds of reactions and controls is shown in the figure below, based on potential response times to a frequency disturbance such as caused by loss of a large generator: Figure 1 Potential response to a power system frequency disturbance Inertial response is provided through acceleration or deceleration of rotating synchronous machines in response to electrical frequency changes; the level of inertia in the power system will determine how fast the frequency changes in the first few seconds of a frequency disturbance. The inertial response of a power system assists in limiting the rate of change in frequency during large disturbances so that control systems have time to respond and intervene. 1 International review of frequency control adaptation, October 2016, available at https://www.aemo.com.au/- /media/Files/Electricity/NEM/Security_and_Reliability/Reports/2016/FPSS---International-Review-of-Frequency-Control.pdf © AEMO 2019 | Final Report – Queensland and South Australia system separation on 25 August 2018 4 Primary frequency control is an autonomous response provided by generator control systems, typically the turbine governors of synchronous generators, which act to arrest frequency disturbances. Primary frequency control typically acts within 6 seconds of a frequency disturbance and provides a response proportional to the magnitude of the frequency disturbance; primary frequency control is a requirement in many power grids as a first line of defence to frequency events and to maintain stable operating frequency2. Primary frequency control can generally only be sustained actively for a short while, but this is sufficient for secondary frequency control to respond. Secondary frequency control restores frequency to normal operating levels through coordination of centralised and local control systems. In the NEM and most other grids around the world, secondary frequency control is largely provided by a centralised automatic generation control system (AGC), which takes tens of seconds to minutes to recover frequency. In the NEM the AGC is operated by AEMO. While not obligatory, active primary frequency control was a common operating protocol for many generators in the Australian power system prior to commencement of the market in the late 1990’s. In the NEM, there is no market or regulatory requirement to provide primary frequency control within the normal operating frequency band of 49.85 to 50.15 Hz. Instead, eight real-time frequency control ancillary service (FCAS) markets operate in the NEM for the provision of frequency control. The two markets for regulation of frequency within the normal operating frequency band are implemented via AEMO’s AGC. There are six contingency FCAS markets that provide reserve to respond to frequency changes when it exits the normal operating frequency band when contingency events occur. Only generators enabled for one of the six contingency FCAS markets are required to respond to a contingency event and only generators enabled for regulation FCAS are required to correct frequency during normal operation. The limitations of secondary frequency control are exposed in the absence of significant primary frequency control, particularly when major contingencies occur. AEMO has assessed the responses of all NEM registered generating systems to the changes in frequency experienced on 25 August 2018. Generation response can be broadly grouped by technology type: Synchronous generation Synchronous generation was providing 96% of the total generation in the NEM at the time of the event. The responses observed from synchronous generation during this event indicated that, unless enabled in the market for frequency control ancillary services (FCAS), many generators either no longer automatically adjust output in response to local changes in frequency or only respond when frequency is outside a wider band (dead-band) than has historically been set. This lack of response resulted in significant technical challenges controlling power system frequency during this event, delaying the resynchronisation of QLD with NSW.
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